1. Field of the Invention
The present invention relates generally to downhole cutting tools used in the oil and gas industry.
2. Background Art
Rotary drill bits with no moving elements on them are typically referred to as “drag” bits. Drag bits are often used to drill very hard or abrasive formations. Drag bits include those having cutting elements attached to the bit body, such as polycrystalline diamond compact insert bits, and those including abrasive material, such as diamond, impregnated into the surface of the material which forms the bit body. The latter bits are commonly referred to as “impreg” bits.
An example of a prior art diamond impregnated drill bit is shown in FIG. 1. The drill bit 10 includes a bit body 12 and a plurality of blades 14 that are formed in the bit body 12. The blades 14 are separated by channels 16 that enable drilling fluid to flow between and both clean and cool the blades 14. The blades 14 are typically arranged in groups 20 where a gap 18 between groups 20 is typically formed by removing or omitting at least a portion of a blade 14. The gaps 18, which may be referred to as “fluid courses,” are positioned to provide additional flow channels for drilling fluid and to provide a passage for formation cuttings to travel past the drill bit 10 toward the surface of a wellbore (not shown).
During abrasive drilling with a diamond impregnated bits, the diamond particles scour or abrade away the rock. As the matrix material around the diamond granules crystals is worn away, the diamonds at the surface eventually fall out and other diamond particles are exposed. Diamond impregnated drill bits are particularly well suited for drilling very hard and abrasive formations. The presence of abrasive particles both at and below the surface of the matrix body material ensures that the bit will substantially maintain its ability to drill a hole even after the surface particles are worn down.
Diamond impregnated bits are typically made from a solid body of matrix material formed by any one of a number of powder metallurgy processes known in the art. During the powder metallurgy process, abrasive particles and a matrix powder are infiltrated with a molten binder material. Upon cooling, the bit body includes the binder material, matrix material, and the abrasive particles suspended both near and on the surface of the drill bit. The abrasive particles typically include small particles of natural or synthetic diamond. Synthetic diamond used in diamond impregnated drill bits is typically in the form of single crystals. However, thermally stable polycrystalline diamond (TSP) particles may also be used.
In a typical impreg bit forming process, the shank of the bit is supported in its proper position in the mold cavity along with any other necessary formers, e.g., those used to form holes to receive fluid nozzles. The remainder of the cavity is filled with a charge of tungsten carbide powder. Finally, a binder, and more specifically an infiltrant, typically a nickel brass copper based alloy, is placed on top of the charge of powder. The mold is then heated sufficiently to melt the infiltrant and held at an elevated temperature for a sufficient period to allow it to flow into and bind the powder matrix or matrix and segments. For example, the bit body may be held at an elevated temperature (>1800° F.) for a period on the order of 0.75 to 2.5 hours, depending on the size of the bit body, during the infiltration process.
By this process, a monolithic bit body that incorporates the desired components is formed. It has been found, however, that the life of both natural and synthetic diamond is shortened by the lifetime thermal exposure experienced in the furnace during the infiltration process. Accordingly, prior art patents disclose a technique for manufacturing bits that include imbedded diamonds that have not suffered the thermal exposure normally associated with the manufacture of such bits. Such a bit structure is disclosed in U.S. Pat. No. 6,394,202 (the '202 patent), which is assigned to the assignee of the present invention and is hereby incorporated by reference.
Referring now to FIG. 2, a drill bit 20 in accordance with the '202 patent comprises a shank 24 and a crown 26. Shank 24 is typically formed of steel or a matrix material and includes a threaded pin 28 for attachment to a drill string. Crown 26 has a cutting face 22 and outer side surface 30. According to one embodiment, crown 26 is formed by infiltrating a mass of tungsten-carbide powder impregnated with synthetic or natural diamond, as described above.
Crown 26 may include various surface features, such as raised ridges 27. Preferably, formers are included during the manufacturing process, so that the infiltrated, diamond-impregnated crown includes a plurality of holes or sockets 29 that are sized and shaped to receive a corresponding plurality of diamond-impregnated inserts 10. Once crown 26 is formed, inserts 10 are mounted in the sockets 29 and affixed by any suitable method, such as brazing, adhesive, mechanical means such as interference fit, or the like. As shown in FIG. 3, the sockets can each be substantially perpendicular to the surface of the crown. Alternatively, and as shown in FIG. 3, holes 29 can be inclined with respect to the surface of the crown 26. In this embodiment, the sockets are inclined such that inserts 10 are oriented substantially in the direction of rotation of the bit, so as to enhance cutting.
As a result of the manufacturing technique of the '202 patent, each diamond-impregnated insert is subjected to a total thermal exposure that is significantly reduced as compared to previously known techniques for manufacturing infiltrated diamond-impregnated bits. For example, diamonds imbedded according to the '202 patent have a total thermal exposure of less than 40 minutes, and more typically less than 20 minutes (and more generally about 5 minutes), above 1500° F. This limited thermal exposure is due to the hot pressing period and the brazing process. This compares very favorably with the total thermal exposure of at least about 45 minutes, and more typically about 60-120 minutes, at temperatures above 1500° F., that occur in conventional manufacturing of furnace-infiltrated, diamond-impregnated bits. When diamond-impregnated inserts are affixed to the bit body by adhesive or by mechanical means such as interference fit, the total thermal exposure of the diamonds is even less.
Another type of bit is disclosed in U.S. Pat. Nos. 4,823,892; 4,889,017; 4,991,670; and 4,718,505, in which diamond-impregnated abrasion elements are positioned behind the cutting elements in a conventional tungsten carbide (WC) matrix bit body. The abrasion elements are not the primary cutting structures during normal bit use.
A second type of fixed cutter drill bit known in the art are polycrystalline diamond compact (PDC) bits. Typical PDC bits include a bit body which is made from powdered tungsten carbide infiltrated with a binder alloy within a suitable mold form. The particular materials used to form PDC bit bodies are selected to provide adequate toughness, while providing good resistance to abrasive and erosive wear. The cutting elements used on these bits are typically formed from a cylindrical tungsten carbide “blank” or substrate. A diamond “table” made from various forms of natural and/or synthetic diamond is affixed to the substrate. The substrate is then generally brazed or otherwise bonded to the bit body in a selected position on the surface of the body.
The materials used to form PDC bit bodies, in order to be resistant to wear, are very hard and difficult to machine. Therefore, the selected positions at which the PDC cutting elements are to be affixed to the bit body are typically formed substantially to their final shape during the bit body molding process. A common practice in molding PDC bit bodies is to include in the mold at each of the to-be-formed cutter mounting positions, a shaping element called a “displacement.” A displacement is generally a small cylinder made from graphite or other heat resistant material which is affixed to the inside of the mold at each of the places where a PDC cutter is to be located on the finished drill bit. The displacement forms the shape of the cutter mounting positions during the bit body molding process. See, for example, U.S. Pat. No. 5,662,183 issued to Fang for a description of the infiltration molding process using displacements.
FIG. 4 shows a prior art PDC drill bit. In FIG. 4, the bit body 100 has thereon a plurality of blades 110. Each of the blades 110 has mounted thereon on mounting pads (shaped according to FIG. 3) a PDC cutting element 112. Each PDC cutting element 112 includes a diamond table 113 affixed to a tungsten carbide substrate 114. The bit body 100 includes suitably positioned nozzles or “jets” 120 to discharge drilling fluid in selected directions and at selected rates of flow.
Different types of bits are selected based on the primary nature of the formation to be drilled. However, many formations have mixed characteristics (i.e., the formation may include both hard and soft zones), which may reduce the rate of penetration of a bit (or, alternatively, reduces the life of a selected bit) because the selected bit is not preferred for certain zones. One type of “mixed formation” include abrasive sands in a shale matrix. In this type of formation, if a conventional impregnation bit is used, because the diamond table exposure of this type of bit is small, the shale can fill the gap between the exposed diamonds and the surrounding matrix, reducing the cutting effectiveness of the bit (i.e., decreasing the rate of penetration (ROP)). In contrast, if a PDC cutter is used, the PDC cutter will shear the shale, but the abrasive sand will cause rapid cutter failure (i.e., the ROP will be sufficient, but wear characteristics will be poor).
When drilling a typical well, a bit is run on the end of a bottom hole assembly (BHA) and the bit drills a wellbore with a selected diameter. However, during drilling operations, it may be desirable to increase a diameter of a drilled hole to a selected larger diameter. Moreover, increasing the diameter of the wellbore may be necessary if, for example, the formation being drilled is unstable such that the wellbore diameter decreases after being drilled by the drill bit. Accordingly, tools such as “hole openers” and “underreamers” have been designed to enlarge diameters of drilled wellbores. These types of tools also may be thought of as using fixed cutters.
In some drilling environments, it may be advantageous, from an ease of drilling standpoint, to drill a smaller diameter hole (e.g., and 8½ inch diameter hole) before opening the hole to a larger diameter (e.g., to a 17½ inch diameter hole) with a hole opener. Moreover, it is difficult to directionally drill a wellbore with a large diameter bit because, for example, larger diameter bits have an increased tendency to “torque-up” (or stick) in the wellbore. When the larger diameter bit torques-up, the bit tends to stick and drill a tortuous trajectory while periodically sticking and then unloading torque. Therefore it is often advantageous to directionally drill a smaller diameter hole before running a hole opener in the wellbore to increase the wellbore to a desired larger diameter.
A typical prior art hole opener is disclosed in U.S. Pat. No. 4,630,694 issued to Walton et al. The hole opener includes a bull nose, a pilot section, and an elongated body adapted to be connected to a drillstring used to drill a wellbore. The hole opener also includes a triangularly arranged, hardfaced blade structure adapted to increase a diameter of the wellbore.
Another prior art hole opener is disclosed in U.S. Pat. No. 5,035,293 issued to Rives. The hole opener may be used either as a sub in a drillstring or may be run on the end of a drillstring in a manner similar to a drill bit. The hole opener includes radially spaced blades with cutting elements and shock absorbers disposed thereon. As described in detail below, embodiments of the present invention relate to hole opening technology in addition to bits, typically found at the end of a BHA.
What is still needed, however, are improved cutting structures that are suited to drill various types of formation.